This invention relates to a process and composition for hydraulically fracturing subterranean formations having an injection means in fluid communication with the subterranean formation. Fracturing is accomplished with an aqueous fracturing fluid, with or without a propping agent suspended therein, which comprises a cross-linked polymeric gel that is syneresis-stable and temperature-stable to at least 250.degree. F. This invention further relates to gelled hydraulic fracturing fluids prepared by a continuous process.
The use of polymer thickened fluids and gels is wide-spread, particularly in the oil industry where such fluids are used for plugging or fracturing operations in oil wells and in flooding for secondary recovery. In many cases, the thickened polymer needs to continue to serve in a thickened state. In others, after the thickened polymer has served its intended purpose, it is often desirable to remove it from the well or formation being treated. To this end, it is necessary to be able to decrease the viscosity of the fluid to a more pumpable state.
Desirable properties of a hydraulic fracturing fluid include high viscosity, low fluid loss, low friction loss during pumping into the well, stability under the conditions of temperature, use and contaminants found, such as in high temperature deep wells, and ease of removal from the fracture and well after the operation is complete.
The fluid loss properties of the fracturing fluid must be low enough to permit build-up and maintenance of the pressures necessary to fracture the formation. Otherwise, low penetration and/or ineffective fractures will be obtained.
Low friction loss is necessary to avoid excessive well head pressures in pumping the fracturing fluid through the casing and tubing and then into the formations. However, the use of high viscosity fracturing fluids is hampered usually due to excessive friction losses encountered during the injection of such fluids into a formation through tubing or casing in the well bore.
Stability under conditions of use, e.g., retention of sufficient viscosity at temperatures in the order of 200.degree. F. and higher for a period of time sufficient to carry out the fracturing operation, is particularly important when the formations penetrated by deep high temperature wells are being fractured. Fracturing materials prepared from many of the prior art materials have no more viscosity than the viscosity of water at temperatures of 200.degree. F. and higher.
Gel instability is evidenced by precipitation and/or syneresis (bleeding or medium separation). The phenomenon of syneresis occurs because the space available for solvent molecules, i.e., water or other medium, in the amorphous network of the gel decreases as the fraction increases of molecular chains that participate in forming crystalline regions within the gel. Accordingly, as the gel "sets", it also "settles" and a supernatant layer of fluid becomes visible over the gel phase. A test of gel stability accordingly is to prepare the gel and to allow it to stand at an increased temperature.
Techniques for hydraulically fracturing subterranean formations by injecting a fracturing fluid down a well and into a formation under sufficient pressure to create fractures in the formation are well known. Commonly, the fracturing fluid is pumped through the tubing or casing in the well bore into the formation to be fractured. The fracturing fluid is pumped at a rate sufficient to open a fracture in the exposed formation and to extend the fracture from the well bore into the formation. Continued pumping of the fracturing fluid containing a propping agent into said fracture results in proppant placement within the fractured zone. Following the treatment, the fracturing fluid is recovered from the well, leaving the proppant remaining in the fracture, thereby preventing the complete closure thereof and forming a permeable channel extending from the well bore into the formation.
The conductivity of the propped fracture depends among other factors on the size of the propping agent particles placed in the fracture. This in turn depends upon the width to which the particular fracture may be opened during injection of the fracturing fluid. The production of wide fractures typically requires that the fracturing fluids have high viscosities. The use of high viscosity fracturing fluids is advantageous since such fluids can support the propping agent particles suspended therein without excessive settling. Relatively large size propping agent particles can be placed in the formation using high viscosity fracturing fluids since wider fractures generally result, reducing the possibility of the propping agent bridging across the mouth of the fracture and accumulating in the well bore, causing what is known as a "sand-out" or a "screen-out."
Preparation of the fracturing fluid can be by a batch process or by a continuous process. In the batch process, the fluid is prepared and held in a holding tank until use which can mean added time and equipment expense, as well as added cost for fluid prepared but not used. In the continuous process the fracturing fluid is prepared at the well site and is discharged directly into the suction of the fracturing pumps. The continuous process is to be preferred usually since it permits more efficient use of fracturing fluid and surface equipment and reduces the need for holding tanks and other equipment. However, the continuous process requires the fracturing fluid be of the required high viscosity by the time the fluid reaches the bottom of the well bore and the fracture in the exposed formation. Accordingly, it is essential that the rate of gellation of the fracturing fluid be controlled to achieve the desired viscosity within a required time period. It is also essential that the increased viscosity be controllable, i.e., capable of being reduced so that after the fracturing fluid has fractured the formation and placed the propping agent in the fracture, the high viscosity is reduced so that the fracturing fluid can be speedily pumped from the fractured formation. The interconnecting pore spaces in the formation adjacent to the fracture are accordingly free from material which could restrict the flow of formation fluids into the fracture.
A variety of high viscosity fluids have been prepared for use in hydraulic fracturing operations. These fluids can be classified as oil-base or water-base fluids depending upon the composition of the continuous phase. The high-viscosity oil-base fluids, typified by gelled hydrocarbon liquids, viscous oils and water-in-oil emulsions are inherently temperature sensitive. Problems also exist in low permeability, tight formations and can require long clean-up periods when used to fracture these formations. The high viscosity water-base fluids include viscous gelled waters, gelled acids and oil-in-water emulsions. Viscous gelled water and gelled acids are based on water-soluble polymers. They possess good proppant suspension capabilities. However, use of such high viscosity water based fracturing fluids is hampered because many of these viscous gelled waters are temperature sensitive--they lose viscosity at higher temperatures which not only reduces the pressure generated in the fracture but also increases the rate at which the fluid leaks off into the formation matrix. Oil-in-water emulsions are difficult to handle and exhibit high friction losses in the well conduit. Furthermore, since pumping equipment and tubular goods available at the wellhead are often limited, the wellhead pressure and hydraulic horsepower required to overcome such friction losses are often prohibitive. That is, a high viscosity fluid often cannot be injected into a formation at a high rate due to excessive friction losses in the well tubing or casing. Such friction losses would require more pump capacity and stronger tubular goods than are normally used.
As gellation rate determines rate of viscosity increase, thus causing the high friction losses encountered during pumping, many attempts have been made to control gellation rate. Dilution techniques as to concentration of polymer and gelling agents have been used. Hydrated fracturing gels have been developed which are pH sensitive and accordingly gel within a predetermined pH range. Methods have been developed to use an already gelled fluid by lubricating the fracturing fluid down the wellbore on a layer of a less viscous fluid which is injected into the well tubing along with the fracturing fluid. All of these methods require either information as to downhole conditions or use of sophisticated injection equipment or pumping equipment and tubular goods not normally available at a wellhead.
I have now devised a composition for fracturing wells which comprises an aqueous liquid of water and an acrylamide-methacrylate copolymer, a cross-linking agent of chromium (III) ion, an activating agent of carbonate ion, a gel stabilizer of an oxalate ion and a breaker of a persulfate ion. Propping agents can be included in the composition. Gellation rate is controlled to cause the gelled fluid to reach a usefully high viscosity at the time it reaches the formation to be fractured, usually approximately five minutes. Friction losses during pumping are accordingly minimized. The influences of conditions within the borehole such as the pH level and temperature are reduced.
I also provide a method of fracturing a subterranean formation penetrated by a wellbore which comprises injecting a composition according to the invention through the wellbore.